Edison International (EIX) Q1 2013 Earnings Report, Transcript and Summary

Good afternoon. My name is Sharon, and I will be your conference operator today. At this time, I would like to welcome everyone to the Edison International First Quarter 2013 Financial Teleconference. [Operator Instructions] Today's call is being recorded. I would now like to turn the call over to Mr. Scott Cunningham, Vice President of Investor Relations. Thank you. Mr. Cunningham, you may begin your conference.

Thanks, Sharon, and good afternoon, everyone. Our principal speakers today will be Chairman and CEO, Ted Craver; and Executive Vice President and Chief Financial Officer, Jim Scilacci. Also with us are other members of the management team. The presentation that accompanies Jim's comments, the earnings press release and our Form 10-Q are available on our website at www.edisoninvestor.com. We will be using the slide materials in our regularly quarterly business update presentation that will be posted tomorrow on our website to support our ongoing investor discussions. During this call, we will make forward-looking statements about the financial outlook for Edison International and its subsidiaries and about other future events. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our SEC filings. We encourage you to read these carefully. The presentation includes certain outlook assumptions, as well as reconciliation of non-GAAP financial measures to the nearest GAAP measure. [Operator Instructions] With that, I'll turn the call over to Ted Craver.

Thanks, Scott, and good afternoon, everyone. This afternoon, Edison International reported first quarter core earnings of $0.77 per share compared to $0.54 per share a year ago. This represents a strong start to the year. The primary driver for our earnings remains Southern California Edison's substantial investments in electric infrastructure supporting public safety, grid reliability and state policy objectives. We also reaffirmed our core earnings guidance for the year at $3.45 to $3.65 per share. Jim Scilacci will review the quarter in detail in his comments. In our year-end 2012 earnings call, I highlighted the 3 mainstays of our commitment to creating long-term value for shareholders. The 3 were: resolving uncertainties and reducing business risk, creating sustainable growth in earnings and dividends and preparing the company for transformative change in our industry. I'll use this same framework for my comments today. Our work to resolve uncertainties and reduce business risk, currently centers on our San Onofre Nuclear Generating Station or SONGS. Safety of the public and our employees remains our paramount goal. Our restart plan for Unit 2 is predicated on this. Also, San Onofre plays an important role in the reliability of the electric system in Southern California. The Nuclear Regulatory Commission continues to evaluate our Confirmatory Action Letter response, which contains our plan to return Unit 2 to service at 70% power for an initial 5-month period. The key now is for the NRC to conclude its work in determining if Unit 2 is safe to operate under these parameters. With its April 16 notice in the Federal Register, the NRC has requested public comments on SCE's proposed license amendment. This amendment would align San Onofre's license with our Confirmatory Action Letter response to the NRC, in which we detailed our return-to-service operating plan for the current roughly 2-year fuel cycle. If approved, SCE would be required to later obtain necessary authorizations for long-term power operation beyond that cycle. The license amendment notice also requests comments on the NRC's proposed no significant hazards consideration determination. This finding is an important procedural step that allows for prompt review of our license amendment request. It's worth noting that this conclusion is what is found in most license amendment requests. The NRC's consideration of our restart plan continues to attract a level of controversy and opposition. Although the license amendment decision is a technical staff decision, the NRC commissioners have the right to review any staff-proposed license amendment decision. Also, the public has the right to file motions to stay issuance of license amendments before the NRC and federal courts. Even if the license amendment is approved by the staff, their approval of our Confirmatory Action Letter restart plan for Unit 2 could still take time. Our overarching desire is for the various outside parties to let the nuclear safety technical work proceed at the NRC to assure a safe and timely restart of Unit 2 without unnecessary delay. Without a restart of Unit 2, a decision to retire one or both units would likely be made before year-end 2013. There are many potential decision scenarios involving Unit 2 and Unit 3. They all have different implications for grid reliability, customer costs, attainment of greenhouse gas and air quality objectives and many other factors. We look to narrow these uncertainties and the potential operating scenarios for both units before the end of the year. We will continue to press for a recovery from Mitsubishi Heavy Industries, the designer and manufacturer of the steam generators. It would not be appropriate, so we won't go into the specifics of our strategy and approach. SCE has moved ahead with its initial outage insurance policy claims under the nuclear insurance program called NEIL. As of December 29, 2012, SCE had filed claims under the outage policy of $234 million, of which our share would be approximately $183 million. These outage claims represent the maximum available recovery applicable for that claims period under the policy. We don't have a clear timeline of when NEIL will make a decision on these or future claims. Any recoveries are expected to be refunded to customers through the E-R-R-A, ERRA balancing account. We continue to believe that the actions taken and costs incurred in connection with the San Onofre replacement steam generators and outages have been prudent. Although it cannot be assured, we continue to believe that all material costs related to San Onofre are recoverable through base rates and the ERRA balancing account, as offset by the potential third-party recoveries I mentioned. We remain in the early stages of the CPUC proceedings to review the rate-making for these various cost categories, and hearings on the reasonableness of 2012 incurred costs are scheduled to begin in mid-May. Also, under the category of reducing uncertainty are the steps taken last year regarding EME. I would note that the examination of the Transaction Support Agreement we reached when EME filed for bankruptcy continues through considerable discovery in the court process. As a result, EME and others have requested extending the target dates for moving this process forward, and our 10-Q discloses that an extension is under discussion. Turning to our efforts to create sustainable growth and earnings and dividends. I'd like to focus on the important enabler of moderating customer rate increases. We must keep rates moderate to facilitate continued support for infrastructure investment. While SCE essentially redoubled its rate base in the past 6 years, this fast pace of growth led to some inefficiencies and rising costs, which can add pressure on customer rates. To counter this, we redoubled our focus on operational excellence and took actions to improve efficiency and get the most from our infrastructure investments. Continued focused on managing costs will help keep rate increases modest for customers. In addition to managing overall rate increases, it is important to design rates that better match costs and avoid burdening one category of customers unfairly. A key policy topic here is rate design. Today's tiered rate structure, which with the implementation of the 2012 GRC is now 4 tiers rather than 5, puts most of the burden of residential rate increases on those who use more power. This includes those with high air-conditioning loads, who live in the warmer inland areas, who sought to escape the high cost of housing on the coast and who can't necessarily afford the increases. We are encouraged by the unanimous committee approval earlier this month of a California Assembly Bill #327, which would remove key barriers to the CPUC creating a new rate design. This bill is supported by a wide range of community, labor and business organizations. We are hopeful that we'll pass the assembly in May, which would then move it to the senate for consideration. Approval will provide the CPUC the authority it needs for the rate design proceeding that it has already launched. SCE will be submitting its initial proposals to the CPUC next month on its rate design proceedings. The third and final strategic element for creating long-term value is positioning our company for transformative change in the electric power industry. We see merit in owning and operating competitive businesses as a matter of corporate strategy. Therefore, we are in the early stages of developing businesses that capitalize on industry change and leverage our knowledge and strengths. Prime areas of interest are distributed generation, electrification of transportation, water purification and power management services to the commercial and industrial sector. These efforts have to be at the right scale and the right pace. We aren't going to bet the farm. They have to be actionable and practical, and they must prove themselves. I don't expect these new initiatives will distract us from our core business at SCE nor should they distract investors. However, I believe it would be foolish to dismiss the potential for major changes in the utility business model. That concludes my comments. I'll now turn it over to Jim Scillaci.

Thanks, Ted, and good afternoon, everyone. I'll start on Page 2 of the presentation. As Ted said, EIX's first quarter core earnings were $0.77 per share, $0.23 ahead of last year. SCE results drove $0.22 of the $0.23 variance. There are a number of components at SCE that will make quarterly comparisons complicated, including the delay in the 2012 General Rate Case decision, SONGS refueling and inspection and repair costs and the completion of the SmartConnect project and elimination of related project costs. On a quarter-over-quarter basis, higher 2013 revenue attributed to a net $0.13 per share to the earnings increase. The biggest difference was driven by the delay in the GRC decision. During 2012, we recorded revenue based on 2011 authorized levels, pending a final decision. Based on the GRC decision, the estimated revenue attributed -- attributable to the first quarter of 2012 was $0.15 per share. During 2012, we also had authorized revenue for the planned refueling outages at SONGS. Because there are no refueling outages in 2013, there was a $0.07 negative variance. We also had an increase in 2013 revenue mainly due to 2 items: a $0.09 per share in CPUC and FERC revenues, partially offset by a $0.04 negative variance from the SmartConnect project. We collect revenue associated with the implementation of SmartConnect this year -- last year and it did not reoccur this year. As everyone is aware, SCE's authorized return on common equity is set at 11 -- excuse me, 10.45% for 2013 compared to 11.5% last year. However, the earnings reduction associated with the lower ROE was offset by the incremental increase in average CPUC and FERC rate base during the first quarter of 2013. Turning to the cost side. There was a net $0.09 per share positive variance in O&M, which was made up of 4 primary elements: first, SONGS inspection and repair costs were $0.04 in the first quarter of last year. In the first quarter of 2013, those costs were less, resulting in a $0.02 per share positive variance. As I mentioned above, the absence of SONGS refueling cost -- outage cost this year provided a positive variance of $0.06 per share. Severance costs in the first quarter of 2013 were $0.03 per share higher, thus, provided a negative variance. Lastly, the SmartConnect project had O&M costs recorded in the balancing account in the first quarter of 2012 of $0.04, resulting in a positive variance this year. The variance of depreciation and interest expense was a negative $0.05 and $0.03 per share, respectively, largely associated with rate base growth. We also recorded expected tax benefits for repair deductions of $0.05 per share, consistent with our 2013 earnings guidance. Finally, taxes and all other provided a positive $0.03 variance. Moving to the parent company and other costs, which are shown on the left part of the slide. These costs are comparable year-over-year, with a $0.01 difference due to a small contribution from Edison Capital. As we have previously said, we are not making new investments in Edison Capital, and we're slowly liquidating the remaining portfolio. We had 2 non-core items in the first quarter. The first was in the parent company and other category, where we had $0.02 per share benefit from a lower-than-expected level of state income taxes from last year's sale of Edison Capital's lease interest in a power plant. The second relates to EME. With EME now de-consolidated for accounting purposes, any changes in tax or other accounting estimates will flow through the income statement as discontinued operations. We recorded a $0.04 per share benefit from updated estimates from future tax de-consolidation of EME. The first quarter of 2012 loss of $0.26 per share reflect the EME losses that were previously part of the financial results prior to bankruptcy. The same presentation will continue for the balance of 2013, and we expect periodic positive or negative adjustments related to EME to be recorded as non-core items and discontinued operations. On Pages 3 and 4, we have included our capital spending and rate base forecasts through 2014. These are unchanged from our year-end financial reporting. Total capital expenditures in the first quarter were $814 million. Currently, we are finalizing our expected capital spending plans to be included in the Notice of Intent for the 2015 General Rate Case, which we will file in the third quarter. Because of an aging infrastructure and reliability needs, we plan to seek an increase in our proposed distribution capital spending. However, we also foresee lower transmission investment as construction of 2 of our major transmission lines are scheduled to be completed later this year. Our goal is to find the right balance amongst safety, reliability and affordability, such that we can achieve our goals with modest total system average rate increases for our customers. Ted has covered most of the developments related to SONGS, which are summarized on Page 5. The various elements the CPUC proceedings are moving ahead, and SCE submitted its final costs on the steam generator project during the quarter. Page 6 updates the SONGS costs and rate base information along the lines that we introduced last year. We have followed the same approach in the first quarter with one change. Reporting of net market costs for replacement power will now follow the approach requested by the CPUC for periodic filings under the Order Instituting Investigation or OII. This is a different methodology than the one we used last year, which followed the traditional E-R-R-A or ERRA balancing account approach. The largest difference is the inclusion of market power costs during the planned refueling outages and foregone energy sales. I'd now like to turn to a couple of regulatory topics, starting with the FERC return on common equity. Please turn to Page 7 of the deck. Settlement discussions in our 2012 FERC formula rate are ongoing. One of the many important issues is the base return on common equity of 9.93%, which is before incentives. Since the last settlement conference in late February, settlement offers are still being exchanged and are expected to continue into next month. The settlement judge has not yet scheduled the next settlement conference but has indicated it likely would be in late May. While the settlement negotiations are confidential, it is reasonable to assume that the FERC's preferred methodology results in a lower ROE today than when SCE filed its formula rate in June of 2011. If a full or partial settlement cannot be reached, then the rate case would proceed to litigation. SCE and FERC lawyers participated in oral arguments before the D.C. Circuit Court of Appeals on the utilities appeal of its 2008 FERC decision on our CWIP return on common equity. The key issue here is FERC's policy to use medium return of the proxy group for utilities filing individually rather than using the midpoint of the proxy group. The decision on the appeal is expected by the fourth quarter. Page 8 shows they'll now approve cost of capital mechanism for CPUC jurisdictional rates through 2015. You can see on the right side of the slide that the period-to-date moving average, which over 12 months, determines whether our change is triggered in the return on common equity, although running it below the starting point is well within the zone that would result in no change and allowed return in 2014. Page 9 shows the reaffirmed core earnings guidance that Ted mentioned. We have updated our GAAP earnings guidance to reflect the first quarter non-core items only. Our 2013 guidance continues to include the same amount of repair deductions, operation and maintenance and other cost benefits and energy efficiency savings we provided during our year-end call in February. I'll close by building on Ted's comments regarding shareholder value proposition. Narrowing the uncertainties around SONGS in 2013 is a key priority for Edison International. We continue to see significant rate base growth potential, reflecting our wires-focused investments program. We will continue to optimize our cost structure, strive for operational excellence and create the foundation for an improved SCE cost structure in our next General Rate Case. Okay. I'd now like to turn over the call for Q&A, operator.

[Operator Instructions] Our first question comes from Dan Eggers of Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Listen, just on SONGS, and I'm sure we'll have a litany of questions on this today. But the idea of kind of more publicly stating a willingness to close the plant if you can't get Unit 2 going. What do you think are the major parameters in making the decision of go, no go, while you're waiting for an NRC decision? Is it a certain level of cost incurred before you get there? Is it a slowness in movement by the staff? Or will there be some sort of CPUC involvement that maybe shape that decision?

Dan, this is Ted. I'll take a crack at your question. I think, principally, the thing to understand is effectively, we're underwriting the costs here until we have certainty around the rate-making treatment. That isn't going to get resolved for some period of time. So there's just, I'll say, a general limit of how much we can continue to rack up these costs without certainty of cost recovery. So I think of it as more of a time issue than anything else. But it certainly is a combination of time and just dollars that effectively we're underwriting with uncertainty about cost recovery. Dan Eggers - Crédit Suisse AG, Research Division: And then I guess in that vein, is there a way to lower costs while you're waiting for a decision on the units? Or do you have to keep them fully staffed at these levels for -- until there is a decision?

It gets complicated, but there's a limit to how much you can pare down costs if you're waiting for a decision on restart because you can't knock down the costs, lay off workers, that type of thing, and expect to bring them back on quickly in order to get the unit restarted. So essentially, you have to run with a level of cost to keep all of the systems at the plant ready to go. So that if we get the decision to restart, we can do so quickly. Again, a large part of what drives us here is SONGS plays a unique role in the reliability of the grid here in Southern California. Its location, as well as its voltage support and, to some degree, the energy produced from it, all of those things are important to reliability. We're about ready to enter our summer period. That's when we have our peak demand, so we want to make sure we're ready to go when the decision comes forward.

Dan, this is Jim. I'll just add to what Ted's already provided you is that, we had already planned, as part of the 2012 General Rate Case, to reduce our staffing at SONGS. We have done benchmarking and determined that it was appropriate to reduce the numbers to more competitive levels. And because of the ongoing problem with San Onofre, we are very carefully watching our expenditures, both capital and O&M, to make sure that we don't create the potential for future stranded costs. And so the capital is very, very -- we're being -- we're watching it very carefully. And only those things that we must do for safety or reliability, we are undertaking. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then just the decision that Ted just -- while you're not going to give a number as to the cost exposure, a decision will be resolved this year, is that fair?

That's what we're trying to signal is that there's a limit on timing and everything else. So we're -- I think it's the first time we've kind of said it that way. But essentially, we're down to months here in terms of being able to have clarity on the NRC decision, as well as clarity on the -- some of the rate-making treatment.

Our next question comes from Greg Gordon of ISI Group.

So in terms of timelines for these issues, looking at Page 5 of your deck, you filed for -- you filed with the NRC the license amendment several weeks ago. Is it correct that there's a -- sort of a specific time frame in which they're expected to respond? And then what are the series of things that have to happen to get you to the point where they either say, "Yes, you can restart," or "No, you can't?"

On the license amendment request -- Greg, this is Ron. There are 30 days for public comment and 60 days for parties to provide a notice to intervene. The commission can make a decision on the license amendment request if there's a no significant hazards consideration following the public comment period. We're not really speculating on when they would make the call. The important thing to remember here, though, is it's the Confirmatory Action Letter response that they have to approve that will give us the permission we need to go forward with the restart.

Okay. But the -- giving you -- if they were to say that those -- that the -- after 30 days, hypothetically, if they come back on the end of day 30 and say, "Okay, you can go ahead and restart," you still have to then, subsequent to that, get an approval of your specific plan before you can actually restart. Is that correct?

After the 30 days, they could approve our license amendment request as a potential. That's just one component of the overall review of our Confirmatory Action Letter response. They have to approve our Confirmatory Action Letter response, which includes the restart plan. That's the pacing item.

Okay. And then with regard to cost recovery, I'm seeing here that the SONGS OII -- the proposed decision is expected Q3 2013. Ted, just to circle back to the comment, the answer you made to Dan's question, you're basically proposing that there's a practical limit to how much shareholders should -- can underwrite here. And if, for some reason, the commission were unable or unwilling to give you a sort of financial parameters by the end of this year, that would cause a significant problem for you?

Yes. I think I'm just going to end up restating the words I used before that what we're trying to signal is it's difficult for us to see kind of continuing to underwrite the costs without clarity on the rate-making treatment, and without clarity on what the NRC decision is going to be. So there's a practical limit to how much we can absorb of that risk. I think the pacing item here at the moment is the NRC decision. But it's really both components that are important to us.

Our next question comes from Steven Fleishman of Wolfe Research. Steven I. Fleishman - Wolfe Trahan & Co.: Just another clarification on the NRC process. So theoretically, you -- we should not necessarily read an approval of the license amendment as a likely trigger that they will approve the Confirmatory Action Letter?

I think they're independent. Or actually, the way I think of it, I think of the license amendment request as sort of a subcomponent of the overall Confirmatory Action Letter. It's just one piece of the puzzle as they look at our Confirmatory Action Letter response and restart plan. Steven I. Fleishman - Wolfe Trahan & Co.: Okay. In the 10-Q, you also say that you do not expect them to rule by June 1. Could you just give more color on the timing issue there? And how you would know that?

It's just our judgment based on exchange of data requests and analysis back and forth between ourselves and the staff. So it's our judgment. Steven I. Fleishman - Wolfe Trahan & Co.: Okay. And you also mentioned these other offers of investigation reviews, et cetera. I mean, is there any -- does that play into the timing as well? And has there been anything -- is that the issue that were in the press a few months ago? Or is there something new there?

The Office of Investigation was in the press a few months ago. The additional disclosure around the Office of Inspector General, which looks at the NRC internally, was a new disclosure. I think the key point we made in our disclosures is there are many parties that are saying those investigations should be completed prior to any decision being made by the NRC. Steven I. Fleishman - Wolfe Trahan & Co.: Okay. One last question, just on the Edison Mission process. Could you just give some more color in terms of what is exactly going on with discovery? This is discovery related to your agreement?

Okay. Steve, this is Jim. We're going to have Bob Adler, our General Counsel, take a shot at that one.

Settlements like this involve an examination process before the bankruptcy court, which is like a judicial process. There is a discovery of documents, interviews, depositions, review of all that. Our lawyers are working very hard on this, as are the other lawyers for other parties. It takes time. There are other proceedings in the bankruptcy. So -- but this is a customary process for settlements like this. There's a -- there is an inquiry about the value of the settlement to the parties.

Our next question comes from Hugh Wynne of Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Just wanted to ask a bit about CapEx and cash flow. You had mentioned your expectation that distribution CapEx will continue to rise while transmission CapEx will tail off in the next GRC. And indeed, I guess, that trend is evident in 2014 already compared to 2013. Are those sort of rise in distribution CapEx and decline in transmission CapEx enough to sort of offset each other, so that we should expect continued capital expenditures more or less at the average level of the '12 through '14 GRC, more or less at the $4 billion level? Or do you see CapEx trending down materially?

Yes. Hugh, this is Jim. We haven't put out a forecast for that period. We're getting very close to that time frame. But I think it's going to be roughly in the same zip code, how about that? Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then if it's roughly in the same zip code, you're freeing up very little incremental free cash. Are we then putting off for a couple of years the increase in the dividend to your target range?

Well, we haven't said anything different there. And we're going to continue with our expressed desire to return to our targeted payout ratio over time. Our target payout ratio, many of you people know, 45% to 55% of the utilities earnings. And our intent is to return over time. We stepped up the dividend slightly last year, and we would look to do that going forward to get back to that targeted ratio.

Our next question comes from Michael Lapides of Goldman Sachs.

Yes. Actually, 2 questions, a little bit unrelated to each other. First, on Edison Mission, what happens if we reach that kind of the milepost date in a couple of weeks and you don't get the extension or the parties can't agree on an extension? What happens at that point in time, meaning if the settlement isn't approved, where do we go from there?

Michael, I'm going to turn it over to Bob Adler again.

Under the transaction support agreement, if a milestone is not reached, then certain parties are able to terminate. It takes an affirmative act to terminate the agreement on 5 days' notice. Pending any such notice, the agreement continues in force for any, as I might add, or us or the bondholders.

And if the agreement is terminated?

If the agreement is terminated, we'd no longer would have a settlement agreement. And I wouldn't speculate on what would happen at that point.

Got it. Unrelated, Ted, you made some comments about investing in some of the non-utility opportunities or the non-utility kind of emerging technologies that seems like -- can you just talk about kind of the range of how much capital you anticipate deploying, what kind of levels of returns you're seeking and whether you've got the appropriate structure in place to actually deliver those returns?

Yes. Well, the returns would be the same way we look at all our businesses in the past. We go through a cost of capital analysis for any and all of our businesses, whether it's utility, non-utility. And we end up with hurdle rates and any contemplated investments have to show that they can meet or exceed that hurdle rate. So that part would be the same. In terms of the amount, I think, all the words were chosen carefully, that we think there's a, more likely than not, some significant changes that are going to take place over the next few years in the industry overall. Probably some of those changes will be more accelerated in certain regions of the country than others. We think ours would probably be one of those. We want to make sure that while we are exploring these things and trying to kind of stay ahead of the curve, that we aren't doing it at too fast a pace or, as I use the phrase, we're not going to bet the farm on all this stuff. We feel it's, as I said, more likely than not that these changes are going to take place. So we think it would be foolish to turn a blind eye to it. But we want to be able to kind of take it one step at a time. And each of these things has to prove themselves along the way. So that's why we say we don't think this will distract us from our core business at SCE. We also don't think it should distract investors from that core business. But it would be foolish to ignore that some of these changes are out there and taking place.

But I mean, do you view this as EIX, may -- Edison International making equity investments in emerging technologies or funds? Or is this a -- kind of a relook at kind of more traditional merchant generation or something dramatically different than either of those 2 alternatives?

Yes. So it's not kind of redoing merchant generation, that I think we can be clear on. We identified, in my remarks, a few of the areas that really have -- are kind of the areas most interesting to us at this point. And those are things like distributed generation, electrification of transportation, I would use the term writ large, it doesn't just mean electric vehicles. In fact, I think most of those electrification opportunities are probably more in the movement of goods than automobiles. Water purification, power management services to commercial and industrial sectors, so those are the areas we've kind of identified. We have different levels of effort underway there. I don't see this as we're going to kind of pretend we're a venture capital company. We're not. I think we look at these things from the standpoint of, are these businesses that can leverage our strengths, leverage our brand and our kind of background? And so they're -- they would be more operating-type activities than venture capital investments. And I think the final piece is we're more interested in actual tangible projects that would have cash flow or service-type activities as opposed to trying to bet on specific technologies or invest in technology companies or companies that manufacture a new technology product. So hopefully, that'll give you a little bit of a sense of where our focus is.

Our next question comes from Jonathan Arnold's line of Deutsche Bank.

Just a quick one on the -- I noticed on your transmission projects slide, the large transmission projects Slide 15, there was a proposed changes to the FERC incentives. Are these decisions that you've had or are they [indiscernible]?

Well, I will pause and look and -- Linda, was there any change?

No.

So there aren't any changes that we have and I don't -- that I'm aware of right now. I think those reflect what we are currently receiving on these projects. That hasn't changed since -- for some time. So maybe we can take you off-line, Jonathan, and we can talk through it after the call.

Recently, we filed update on Devers-Colorado River estimates, but we had it in last year's or year end as well.

But it was on at 125 in the last business update, I think. And now it's 100? And the -- and then Eldorado was -- had a number and now it's an NA [ph].

I think he's talking about incentive [indiscernible] dollars.

We can see the incentives, right?

Yes, there's been no changes to the incentives.

Our next question comes from Ali Agha of SunTrust.

Ted, I wanted to clarify some of the earlier remarks, just to be clear on a couple of things. One -- first, on the SONGS, if I'm hearing you right, I mean, previously, you had requested the NRC to give you a decision for the Unit 2 restart on May 24 so you could start by June 1. Am I hearing you right that, that's unlikely -- that timeline will unlikely be correct? So if that's the case, what's the timeline we should be roughly thinking about now?

I think the answer to your first question is yes. And I don't think we're putting a date out there because we're continuing to have discussions with the NRC and the staff in terms of what's going on. And I think I'll pause there and see if, Ron, you want to add anything more. Because I think it's -- purposely, we don't have a date is the answer. And we're going to just continue to work through it until we know more.

Right. We wanted the NRC to proceed without unnecessary delays, and target dates were intended to emphasize the importance of running this summer. With regards to the broader decision, I think Ted said it earlier, we're looking at bigger decisions by the end of the year.

Right. And also, just to clarify that point, I mean, as far as I can tell, you won't have much clarity, or at least from what we've gathered, on Unit 3, by the end of the year, haven't heard anything at all to suggest that, that is reaching a conclusion on the Confirmatory Action Letter or what have you. So just to be clear, I mean, assuming that you get this Unit 2 restarted, I mean, is the likelihood, if I'm hearing you right, that Unit 3 most likely gets retired? Or what would have happened by year end to give you comfort on turning [ph] on Unit 3?

I think on Unit 3, in our disclosures, we said that could go beyond year end, depending on what we observe should Unit 2 restart and we get some information when we go in and reinspect it.

Right. So I am trying to reconcile that with Ted's remarks about retirement decisions by year end. How do you make that decision if you're not clear on Unit 3's status by that time?

Again, I think in our disclosure, we said that Unit 3 could slip beyond year end, depending on what we observe on Unit 2 should it restart.

Okay. And last question, Jim, if I could. Going back to your point on the CapEx, you're looking at beyond the current rate case cycle. If assuming that's in the same zip code, to use your words, would that imply -- I'm assuming it would, just to be clear, that rate base growth over that period should be in a similar zip code as well?

Yes, I think this -- capital expenditure's zip code and rate base are going to be similar, because they drive one another. So the answer to the question is yes.

Our next question comes from Stephen Byrd of Morgan Stanley.

Most of my questions have been asked and answered. I just wanted to follow up on the EME and the request for further time. I just wanted to check, in terms of potential movements that could have in terms of your ultimate tax position, should we be thinking about any potential forward movement in terms of your ultimate net tax position? Or is this likely just further discovery, further deliberations but we shouldn't be thinking about major changes in cash taxes out?

This is -- the discussion is around the proceedings and the process of the proceedings, not the -- and the timing of that, not the substance of the agreement, if that's your question.

Okay. So the -- yes, so it's really -- so obviously, the agreement could always be terminated, I guess, if things didn't go well. But absent that, it's not as if some tax position could change as a result of these discussions of this delay. Is that right?

We're just talking about the timing and the proceeding. It's not affecting the tax position at all.

Our next question comes from Paul Fremont of Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: I guess my first question has to do with the ability of Unit 2 to operate at levels above 70%. It seems as if the steam quality problem is resolved at a lower level of operation. So is there anything that the company is basically able to do, assuming that the restart is allowed that would enable that plant to go beyond 70% on a long-term basis?

Yes. Let me handle that one. I don't think we want to get into a lot of speculation about future power levels and those types of things at this point. What we've proposed is 70% for 5 months. And then we're going to take it down and reinspect it. I think the key objective at this point was to put forward a plan that we knew had lots of margin for safety around it, and that was the focus. So this is a first-of-a-kind event. We wanted to make sure we had abundance of safety margin. Once we get clearance, assuming we get that and we have the operating period, then there's opportunity to think in terms of whether different power levels are appropriate. But at this point, the focus is just on coming forth with a plan that has sufficient safety margin for a first-of-a-kind event. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Well, maybe I -- maybe just to rephrase my question, I mean, what -- has the company determined what the fix would be to the current problem? I mean, other than the fact that, at lower levels of operation, you don't get that, that doesn't happen. But is there something that sort of proactively would fix the problems that you've identified?

I don't think I'll attempt to restate my words. I just would say it the same way I did. So the focus here has been to make sure that we have sufficient safety at the restart plan that we put forward. We believe it does. That's what the NRC has to determine in its evaluation and mostly where we go from there. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. I guess my follow-up would be, in the Q, you talk about the fact that you've been advised by Mitsubishi that a possible course of action would be the replacement of significant portions of the steam generator, a process that could take more than 5 years. What -- under what scenario would that potentially be something that you might pursue?

Well, I don't think we're really prepared at this point to try to speculate about those types of things. I think, really, where we are right now is trying to get restart approval for the plan that we put place, which, as I said, has sufficient safety margin around it.

Our next question comes from Andy Levi of Avon Capital.

Just a very quick question. So just back on SONGS, it just sounds like to me that the process could be delayed because of interveners and other people kind of filing appeals, and is that of kind of what you're saying and could stretch into year end or a longer period? And is that where the concern is for you guys beyond, obviously, trying to get it restarted and the mechanical aspect of it?

Yes. I don't think that's the primary concern. I don't think that helps the timing because it just ends up creating more work for the NRC staff to have to go through. But the primary, really, determination here is a safety determination. That's one that the staff makes. So this issue regards a specific plant that has a safety issue. So this is a matter for the technical staff to work through, and they are. Depending on what that answer is, then we'll know where we are on that point. The intervener piece and all of the other stuff that's been surrounding this, I don't think is the central issue at this point.

I understand that's not the central issue. That I definitely get. But is it possible that various different parties, through appeals and kind of the legal process of going through NRC approval, could end up holding this up for a period of time?

I guess anything is possible. We outlined that or I outlined that in my remarks what some of those procedural things might be. But I think, at this point, if things went kind of, if I could put it this way, typically, then this is primarily a safety -- technical safety issue, which the NRC staff would really come to its conclusion after it's gone through its analysis. And I think all the other pieces are probably more things that happen in response to the process as opposed to the substance of the issue. At any rate, our primary focus right now is the safety determination. And presumably, we'll hear from the NRC on that in due course.

And our last question will come from Neil Kalton of Wells Fargo.

I had another question on SONGS. If the decision is made to retire these units ultimately, how should we think about the possible implications on capital spending? Would there be incremental spending needs? Would they be contemplated in the zip code comments you made previously about '14 to 6 -- or '15 to '17? Or would that be incremental?

Neil, this is Jim. I think we're in the process of preparing our GRC, and it's going to cover the periods '15 through '17. And we'll contemplate, in that process, appropriate levels of capital expenditures. And I think, really, the time frame for when you could see potential higher capital expenditures could be beyond that '15 through '17 period. Because you've got confluence of events. It could be SONGS. You've got -- once your cooling-related features, you have the other potential outages. Though I think it's a little further out than the next year. See -- I'll look over at Linda Sullivan and see if you agree. She's agreeing with me.

And that was the last question. I'll now turn the call back over to Mr. Cunningham.

Thanks very much, everyone, for joining us today. And please call us if you have any follow-up questions. Thank you, and good afternoon.

This concludes today's conference. Thank you for your participation. You may now disconnect.